Identifying the optimum geographic and stratigraphic target(s) for oil and gas exploration or development is a critical decision to be made. Drilling of wells is costly, often amounting to hundreds of millions of dollars for a reservoir, depending on the number and types of wells involved. Once wells are drilled, there is no flexibility in changing their surface or stratigraphic position later. The only possible alteration is to drill additional stratigraphic targets or recomplete existing wells, but the surface location will remain unchanged.
Typically, the selection process for locating wells utilizes available technology such as saturation applications, pressure distribution maps, isopach maps, rock quality maps, and so forth. There is an increased focus on quickly identifying the number and quality of potential horizontal target zones in unconventional plays. This processes to improve the quality of wells placement then leads to better decision making.
Assessing well placement is usually a two-step process. The first, and most challenging, step of the process is to identify “sweet spots” in a reservoir. Sweet spots are the most productive position for a horizontal well in terms of both stratigraphic space and map location. The second step includes the optimization formulation or method to be used.
Unconventional reservoirs continue to be a global strategic resource actively exploited by E&P companies. However, in unconventional reservoirs, sweet spot recognition is essential to reducing uncertainty, high-grading acreage, pinpointing the best drilling in the acreage, and improving field economics. Identifying such sweet spots require a detailed understanding of complex reservoir properties and how these properties influence the productivity of the wells. This involves large amounts of data, including stratigraphic horizons, faults, lithological properties, and organic content.
Thus, the most significant challenge for the subsurface screening of unconventional plays, including source rock, hybrid, and tight sand reservoirs, is the determination of the sweet spot. Traditional stratigraphic screening methodologies target the zone with the highest quality rock within a predefined geological formation. A hypothetical horizontal well bore is then centered around this point and the in-place hydrocarbon volumes are calculated using rock quality cutoffs. The hydrocarbon fluid properties are typically dealt with in a stochastic model later in the screening workflow. This method presents several problems:
A target zone principally centered around the highest rock quality may not equate to the stratigraphic sweet spot defined by maximum in-place volumes. The sweet spot will likely include any one zone of reservoir that is of very high quality, but may be more difficult to define when the range and distribution of the reservoir quality is highly variable, as is the case for some hybrid plays with thick and heterogeneous quality reservoir. During the screening process, it is difficult to determine whether a zone with several thin but high quality zones would be better than another with a thick zone of moderate quality rock. In all cases, determining the maximum in-place volume using traditional methods would require iterative forward modeling. The sweet spot should ideally be defined by the integral of in-place volumes across the height of the landing zone.                Only the single best target zone is immediately identified. For unconventional plays, there may be potential for multiple, stacked landing zone targets. For the purpose of exploration screening, any and all intervals that exceeds a user defined minimum in-place volume should be flagged for further investigation.        Excluding the hydrocarbon fluid properties from the stratigraphic sweet spot determination ignores a key risk for many unconventional plays. Certain plays or basins may require specific gas-oil-ratios, viscosity ranges, or working pressures to be economical. Though they do not typically supersede in-place volumes in priority, fluid properties are an important way to characterize potential resources.        Applying rock quality cutoffs (typically for porosity and water saturation) underestimates in-place volumes, especially for low quality rocks. This practice, though appropriate for conventional reservoirs, is commonly used to define a ‘net’ reservoir with respect to the gross interval. Due to the distributed nature of unconventional reservoirs and the improved completion techniques (e.g. fracture stimulation) being applied to the target zone, we believe it is more appropriate to include the low quality reservoir component in the in-place volumetric calculation and sweet spot identification.        Limiting the screening to pre-defined geological formations (or any other pre-defined zone) may prevent the sweet spot from being identified. Where the maximum in-place volumes straddle a boundary, the accumulation would be reported individually within two separate zones. Therefore, the sweet spot may be missed during the screening process.        The time-consuming iterative nature of the traditional volumetric workflow and the delayed incorporation of fluid properties slow down the screening process. When new logs, rock quality, or fluid properties are incorporated, new analyses and models must be run.        
However, further improvements are needed. Even incremental improvements in technology can mean the difference between cost effective drilling and reserves that are unable to recover the economic costs of production. Thus, what is needed are quick and efficient methods of determining the sweet spot. Ideally, the methods can be applied early in the exploration and development phases and can be used with all unconventional plays.